Methods and Units for Mitigation of Carbon Oxides During Hydrotreating

ABSTRACT

This invention relates to methods and units for mitigation of carbon oxides during hydrotreating hydrocarbons including mineral oil based streams and biological oil based streams. A hydrotreating unit includes a first hydrotreating reactor for receiving a mineral oil based hydrocarbon stream and forming a first hydrotreated product stream, and a second hydrotreating reactor for receiving a biological oil based hydrocarbon stream and forming a second hydrotreated product stream.

BACKGROUND

1. Technical Field

This invention relates to methods and units for mitigation of carbonoxides during hydrotreating hydrocarbons including mineral oil basedstreams and biological oil based streams.

2. Discussion of Related Art

Recent air quality issues and production of greenhouse gases has focusedimprovement efforts on transportation fuels. Efforts to reduce emissionsfrom transportation fuels have led to an increase in hydrotreating atrefineries, such as to reduce sulfur content of the transportationfuels. Other efforts focus on renewable sources for transportationfuels, such as to reduce net carbon footprints for transportation ofgoods, people, and/or services.

However, even with the above technology in transportation fuels, thereremains a need and a desire for hydrotreating methods and units thatconsume less hydrogen, have higher catalytic activity, suffer lesscatalyst deactivation, provide increased capacity, have reduced capitalcosts, and can process a variety of feedstocks.

SUMMARY

This invention relates to methods and units for mitigation of carbonoxides while carrying out a hydrotreating process with hydrocarbonstreams including mineral oil based streams and biological oil basedstreams. This invention includes hydrotreating methods and units thatconsume less hydrogen, have higher catalytic activity, suffer lesscatalyst deactivation, provide increased capacity, have reduced capitalcosts, can process a variety of feedstocks, and/or the like.

According to a first embodiment, the invention includes a method ofhydrotreating hydrocarbons. The method includes a first step of feedinga mineral oil based hydrocarbon stream to a hydrotreating unit underhydrotreating conditions in the presence of a hydrotreating catalyst toform a hydrotreated product stream. The method includes a second step ofmeasuring a sulfur content of the hydrotreated product stream, and athird step of starting co-feed of a biological oil based hydrocarbonstream to the hydrotreating unit. The method includes a fourth step ofmeasuring the sulfur content of the hydrotreated product stream duringco-feed, and a fifth step of stopping co-feed of the biological oilbased hydrocarbon stream upon the sulfur content of the hydrotreatedproduct stream reaching a predetermined value. The method includes asixth step of measuring the sulfur content of the hydrotreated productstream after stopping co-feed. The sulfur content of the hydrotreatedproduct stream returns to a value of close to before the co-feed afterthe step of stopping the co-feed.

According to a second embodiment, the invention includes a hydrotreatingunit for processing mineral oil based hydrocarbon streams, biologicaloil based hydrocarbon streams, and/or the like. The unit includes afirst hydrotreating reactor for receiving a mineral oil basedhydrocarbon stream and forming a first hydrotreated product stream, anda second hydrotreating reactor for receiving a biological oil basedhydrocarbon stream and forming a second hydrotreated product stream.

According to a third embodiment, the invention includes a hydrotreatingunit for processing mineral oil based hydrocarbon streams, biologicaloil based hydrocarbon streams, and/or the like. The unit includes ahydrotreating reactor for receiving a feed stream and forming ahydrotreated product stream, and a hydrogen recycle system forseparating and returning unconverted hydrogen to the hydrotreatingreactor as a hydrogen recycle stream. The unit includes a carbon oxideremoval system for removing at least a portion of carbon oxides from thehydrogen recycle stream.

BRIEF DESCRIPTION OF THE DRAWING

The accompanying drawings, which are incorporated in and constitute apart of this specification, illustrate embodiments of the invention and,together with the description, serve to explain the features,advantages, and principles of the invention. In the drawings,

FIG. 1 schematically shows a hydrotreating unit, according to oneembodiment;

FIG. 2 schematically shows a hydrotreating unit, according to oneembodiment;

FIG. 3 schematically shows a hydrotreating unit, according to oneembodiment;

FIG. 4 schematically shows a hydrotreating unit, according to oneembodiment;

FIG. 5 schematically shows a carbon oxide removal system, according toone embodiment;

FIG. 6 schematically shows a hydrotreating reactor, according to oneembodiment; and

FIG. 7 schematically shows a hydrotreating reactor, according to oneembodiment;

FIG. 8 shows a graph of time versus product sulfur level content,according to one embodiment;

FIG. 9 shows a graph of time versus product sulfur level content,according to one embodiment;

FIG. 10 shows a graph of time versus product sulfur level content,according to one embodiment;

FIG. 11 shows a graph of time versus a ratio of product sulfur levelcontent, according to one embodiment;

FIG. 12 shows graph of rape seed oil content versus a ratio of productsulfur level content, according to one embodiment; and

FIG. 13 shows graph of rape seed oil content versus a ratio of productsulfur level content, according to one embodiment.

DETAILED DESCRIPTION

This invention relates to methods and units for mitigation of carbonoxides while carrying out a hydrotreating process with hydrocarbonstreams including mineral oil based streams and/or biological oil basedstreams.

Triglycerides and other suitable biologically derived feedstocks can beconverted into transportation fuel components, such as biogasoline,biodiesel, and/or biodistillate. Triglycerides can include a range ofnatural materials formed from esterification of fatty acids and/orglycerol, such as vegetable oils, animal fats, and/or the like.Coprocessing of natural oils and/or fats with fractions of crude oil,such as, gas oil in a hydrotreater can be a convenient way of convertingthe natural oils and/or fats in to a transportation fuel.

In an oil refinery, hydrotreaters may perform chemical conversionsand/or reactions, such, as hydrodesulfurization, hydrodenitrogenation,hydrodearomatization, and/or the like. These chemical conversions can beused for production of clean and/or low sulfur transportation fuels. Asuitable catalyst used for hydrotreating can include cobalt andmolybdenum on an alumina support. During coprocessing of natural oilsand/or fats, the catalyst can also perform hydrodeoxygenation.

Co-feeding natural oils and/or fats to petroleum hydrotreating processescan result in a loss of activity (deactivation and/or inhibition) of thecatalyst. According to one embodiment, the invention relates to recoveryof desulfurization activity of a hydrodesulfurization catalyst, whenused in coprocessing mineral oil and/or biological oil (bio-oil) byperiodically turning off the bio-oil feed. The presence of bio-oil cancause and/or show the following observable effects: an initial increasein sulfur levels of the product hydrocarbons followed by a more gradualcontinuing increase in sulfur levels. Once the bio-oil feed ceases, theoriginal sulfur levels in the product can be restored.

Desirably, a balance between sulfur levels in a product and the abilityto coprocess biological oil in existing refinery hydrotreatmentequipment can be achieved by operating the process in a campaign-typemode, where addition of bio-oil only occurs periodically,intermittently, and/or cyclically.

Generally during processing bio-oil, increased hydrotreating processeffluent sulfur content can be observed for cobalt molybdenum containingcatalysts (generally low pressure hydrodesulfurization service), butsulfur content may be at least relatively stable with nickel molybdenumcontaining catalysts (generally high pressure hydrodesulfurizationservice). The methods and techniques of the invention can be applied toany suitable catalyst at any suitable conditions.

Addition of octanol (C8 alcohol) as opposed to fatty acid biologicaloils may not cause a reduced loss of desulfurization activity. Accordingto one embodiment, bio-oil can be converted to a linear alcohol, such asbefore hydrotreating.

According to one embodiment, the invention relates to recovery ofdesulfurization activity of a cobalt molybdenum basedhydrodesulfurization catalyst, when used in coprocessing mineral oil andbio-oil by periodically turning off and/or terminating a bio-oil feed.Operating strategies and/or techniques based on this phenomenon may beused and/or practiced to lengthen a lifetime of hydrodesulfurizationcatalyst used in bio-oil coprocessing applications and/or increase ahydrotreating unit capacity.

According to one embodiment, the invention can include a single stagehydrotreater with bio-oil co-feed. The bio-oils can be more reactivethan mineral based gas-oil. Bio-oils can have a higher hydrogenconsumption; and an increased gas yield, such as more methane, ethane,ethylene, propane, propylene, and/or the like. For example, replacementof about 5 weight percent of gas-oil with vegetable based oil (veg-oil)at the same total feed-rate can cause (a) a higher hydrogen make-up rateand increased purge rate to maintain a same recycle purity of a hydrogenrecycle stream, and (b) an increased exotherm in the reactor, such asfrom the deoxygenation of the veg-oil.

According to one embodiment, a hydrotreating unit may include apreheater designed to minimize veg-oil degradation. The hydrotreatingunit may include a high hydrogen consumption along with an associatedexotherm when processing veg-oil versus when not processing veg-oil. Thehydrotreating unit may include a temperature control device and/orscheme, such as a high pressure liquid quench, and/or the like. Thehydrotreating unit can also include a gas circulation rate withrelatively high flow rates (C1-C3 compounds, hydrogen, and/or the like)and the hydrotreating unit can handle more water, such as formed fromprocessing the veg-oil. The hydrotreating unit can include catalyst tohandle carbon oxides and may include carbon dioxide hydrogenation (suchas to form methane and water) and/or carbon dioxide scrubbing. Thehydrotreating unit may have reduced capital costs compared to anotherunit, such as effectively diluting the veg-oil to maintain the exothermunder control can allow lower alloy and/or milder steel vesselconstruction and/or fabrication.

According to one embodiment, the invention can include a single stagegas oil hydrotreating unit (main reactor) with a side-stream veg-oilhydrotreater (second reactor). The second reactor can be used in a samegas circuit as the main reactor, such as with the same compressors andhigh pressure separator. Both reactors can operate at nominally the samepressure and/or circulation (treat) gas composition. Catalyst used inthe second reactor can be the same or different than catalyst used inthe main reactor. Desirably, the catalyst for the second reactor can besomewhat sulfur tolerant. The second reactor can be any suitable size. Aratio of the main reactor volume to the second reactor volume can bebetween about 100:1 to about 1:100, between about 20:1 to about 1:20,about 1:1, and/or the like. Any suitable amount of the hydrotreatingprocess effluent (product) can be based on co-feeding veg-oil, such asbetween about 0 weight percent and about 100 weight percent, betweenabout 5 weight percent and about 25 weight percent, and/or the like of atotal feed to a hydrotreating zone and/or unit.

The hydrotreating unit with the main reactor and the second reactor (inseries configurations and/or parallel configurations) may minimizeand/or reduce an impact of co-feed on the main reactor. The combinedproduct of the reactors can reduce and/or simplify handling of highcloud-point veg-oil based product. The combined unit with two reactorscan have reduced capital costs compared to separate units, such as byutilizing a common gas separator, a common gas compressor, other recycleequipment, and/or the like. The second reactor can be optimized forveg-oil treatment, such as by selecting appropriate catalysts, reactortemperatures, and/or the like. The second reactor may use a more acidiccatalyst designed to perform isomerization and/or cracking, such as toimprove cold-flow properties of the product, for example.

According to one embodiment, the invention can include a single stagegas oil hydrotreater (main reactor) with veg-oil hydrotreater (secondreactor) in a hydrogen make-up circuit. A hydrogen make-up rate to theunit can provide enough flow of hydrogen (treat) gas for the mainreactor and second reactor. In this configuration, the second reactoressentially can operate on once through hydrogen. An optional make-upsupply can be connected to the main reactor. This configuration canallow the second reactor to be fully optimized in terms of catalystchoice and/or reaction conditions, such as temperature and/or pressure.This configuration can offer more options for veg-oil product upgradebecause the veg-oil reactor does not contact a sulfur containingfeedstock (parallel hydrotreaters). This configuration can allowhydrodesulfurization to occur without competition of thehydrodeoxygenation and associated inhibiting byproducts (carbon oxidesand/or water). The second reactor may use a precious metal catalyst andmay be easier to construct than side-stream reactor, such as bysimplifying piping in the hydrogen recycle system.

Principle components of bio-oils can include triglycerides, pyrolysisoils, other suitable compounds, derivatives of other biologically basedcomponents, and/or the like. Triglycerides can be formed from threefatty acids (branches) attached to a glycerol backbone (3 carbon atoms).The fatty acids may have a carbon chain length of any suitable number,such as between about 12 and about 24 carbon atoms. The bio-oils can befully saturated and/or have one or more unsaturated double bonds in thehydrocarbon chain and/or branch. Generally, bio-oils can be low insulfur content, but may have oxygen and/or nitrogen heteroatoms.

Triglycerides can be upgraded to biodiesel products by using variousprocesses which can include esterification, hydrogenation,decarboxylation, and/or the like. Hydrogenation can consume a largeamount of hydrogen with a portion forming the reaction product water.Increased hydrogen consumption can be expensive due to capital and/oroperating costs of hydrogen supply. Decarboxylation can form methane ascarbon dioxide hydrogenates. Hydrotreater operations can seek tominimize carbon dioxide formation, such as may reduce hydrogenconsumption, reduce potential corrosion problems, reduce potentialmetallurgical issues, and/or the like. Carbon dioxide levels can becontrolled with a purge stream. The purge stream can include hydrogenfurther increasing hydrogen consumption. The purge stream can be burnedas fuel gas, flared, recovered in a hydrogen recovery unit (cryogenic,adsorption, absorption, membrane, and/or the like), sent to a sulfurrecovery unit (Claus unit and/or the like), returned to a hydrogen plantfront end for clean up (before and/or after a reformer, for example),and/or the like.

According to one embodiment, the invention can include a fixed bedhydrotreater with a co-feed of bio-oil with feed of mineral oil. Thehydrotreater reactor system can operate at a relatively low hydrogenpressure, such as less than about 30 bars. The hydrotreater can operateat a high bio-oil content, such as greater than about 30 weight percentof fresh feed. The hydrotreater can use a cobalt and molybdenum catalyston an alumina support. The hydrotreater can include a carbon dioxidescrubbing device in a recycle gas system. The carbon dioxide scrubbercan include an amine and/or a promoted amine, such as monoethanolamine,diethanolamine, and/or the like. The carbon dioxide scrubber can includea membrane to separate carbon dioxide from hydrogen, such as a polymericmembrane, a ceramic membrane, a metal film membrane, and/or the like.The carbon dioxide scrubber can include a solid adsorbent, such as azeolite, a molecular sieve, an activated carbon, an amorphoussilica-aluminate, and/or the like. The carbon dioxide scrubber caninclude a basic oxide formed from an alkali metal (Li, Na, K, Cs, and/orthe like), an alkaline earth metal (Mg, Ca, Sr, Ba, and/or the like), arare-earth metal (La, Ce, and/or the like), and/or the like. Theadsorbent could be regenerated thermally at a suitable temperatureand/or with a suitable medium and/or carrier gas. The carbon dioxide maybe suitable for industrial applications, food applications, beverageapplications, medical applications, liquefaction, solidification,sequestration, and/or the like.

According to one embodiment, the invention can include a hydrotreaterwith an interbed purge. A multiple bed reactor can include interbedremoval of process gas, such as hydrogen, carbon dioxide (inhibitingbyproduct), other light gases, and/or the like. The reactor can includeinjection of fresh hydrogen (make-up and/or recycle following a carbonoxide removal system) to each bed. Any suitable amount of flow throughthe bed can be used for the interbed purge, such as between about 0volume percent to about 100 volume percent, between about 5 volumepercent and about 50 volume percent, between about 10 volume percent andabout 30 volume percent, and/or the like.

According to one embodiment, the invention can include a fluidized bedhydrotreater, an ebullated bed hydrotreater, and/or the like. Thecatalyst may include any suitable particle size. A portion of thecatalyst can be withdrawn from the reactor on a continuous basis and/oran intermittent basis (batch) to be regenerated. Catalyst regenerationcan occur in a main reaction zone, a separate zone, a separate vessel,and/or the like. Regeneration can be done with hydrogen, water, steam,oxygen, and/or the like.

Some potential benefits of the hydrotreater units of the invention caninclude reduced hydrogen consumption, production of concentrated carbondioxide streams, improved environmental performance by lower greenhousegas emissions, and/or the like. According to one embodiment, theinvention includes adding a carbon dioxide removal step and/or system incombination with low operating pressures. The carbon dioxide removalsystem may also remove hydrogen sulfide, nitrogen oxides, and/or thelike from the recycle gas.

According to one embodiment, the invention can include a process for theproduction of hydrocarbons. The process can include the step of (a)feeding hydrogen and a first feedstock including one or morehydrocarbons to a first reactor to produce a first hydrogenated productstream including hydrocarbons present in or derived from the firstfeedstock, and the step of (b) feeding hydrogen and a second feedstock(bio-oil), such as including a carboxylic acid, a phenol, a ketone, analcohol, derivatives thereof, and/or the like, to a second reactor toproduce a second hydrogenated product stream including hydrocarbonsderived from the bio-oil. The process can also include the step of (c)feeding the first hydrogenated product stream and second hydrogenatedproduct stream to a separator, and the step of (d) removing from theseparator a liquid hydrocarbon phase including hydrocarbons from thefirst hydrogenated product stream and from the second hydrogenatedproduct stream, and a vapor phase including unreacted hydrogen andvolatile components present in the first and second feedstocks, andproduced in the hydrogenation reactions in the first and secondreactors.

This configuration can include and/or produce two separate hydrogenationreactions, hydrogenation of a first hydrocarbon-containing feedstocktakes place in a first reactor, and hydrogenation of a second feedstockincluding a bio-oil takes place in a second reactor. Two reactors can beoperated concurrently, although separate batch processing may be used. Aproduct stream from the first reactor (the first hydrogenated productstream) can include hydrocarbons that are present in and/or derived fromthe hydrocarbon-containing oil (mineral). A product stream from thesecond reactor (the second hydrogenated product stream) can includehydrocarbons produced from the reaction between hydrogen and thebio-oil.

The process can be used in the production of liquid hydrocarbon fuels,for example gasoline, diesel, aviation gasoline, jet fuel, kerosene,fuel oil, bunker oil, and/or the like. Light hydrocarbons can also beproduced by the process, for example one or more C1 to C4 hydrocarbonswhich may be paraffinic in nature. The light hydrocarbons can be used inthe production of gaseous hydrocarbon fuels, LPG (liquefied petroleumgas), and/or the like. According to one embodiment, the hydrocarbonfuels can be used directly and/or for blend stocks in products meetingand/or complying with industry standards and/or regulations.

According to one embodiment and in the first reactor, a first feedstockincluding one or more hydrocarbons contacts with hydrogen to produce afirst hydrogenated product stream. The hydrocarbons in the firsthydrocarbon-containing feedstock may be predominantly paraffinichydrocarbons, but can also include other hydrocarbons. Otherhydrocarbons may include unsaturated hydrocarbons, olefins, aromatics,heteroatom containing organic compounds, organonitrogen compounds,organosulfur compounds, and/or the like.

The first feedstock may be derived from gas, coal, biomass, othersuitable raw materials, and/or the like. The raw materials may beconverted to syngas (synthesis gas) through processes, such as steamreforming, partial oxidation, gasification, and/or the like. The syngascan be subsequently converted to hydrocarbons through Fischer-Tropschsynthesis, other suitable gas to liquids processes, and/or the like.

According to one embodiment, the one or more hydrocarbons in the firstfeedstock can be derived from crude oil. Crude-oil derived hydrocarboncompositions can be higher in heteroatom-containing organic compoundscompared to Fischer Tropsch-derived oils. The first feedstock caninclude hydrocarbons derived from one or more process streams associatedwith crude oil refining, for example straight-run fractions, naphtha,kerosene, light gas oil, heavy gas oil, vacuum gas oil, light cycle oil,heavy cycle oil, coker naphtha, visbroken naphtha, coker gas oil,visbroken gas oil, and/or the like. Additionally and/or alternatively,it may be derived from or include hydrocarbons produced by one or moreother refinery processes, such as cracking, catalytic cracking,hydrocracking, reforming, coking, dearomatization, isomerization,alkylation, and/or the like.

Sulfur compounds may include carbonyl sulfide, hydrogen sulfide,mercaptans, sulfides, disulfides, cyclic thioethers, polycyclicthioethers, aromatic thioethers, thiophenes, benzothiophenes,dibenzothiophenes, alkyl-substituted sulfur derivatives, and/or thelike. Sulfur compounds can be present in total at concentrations greaterthan those allowed in the desired fuel by state and/or governmentalregulatory authorities. Sulfur content of the hydrocarbon-containing oilcan be any suitable value, such as about 0 parts per million or more,about 200 parts per million or more, about 0.1 weight percent or more,between about 0.2 weight percent to about 2 weight percent, and/or thelike, expressed as elemental sulfur. Olefins, content of thehydrocarbon-containing oil can be about 0 weight percent, greater thanabout 0.01 weight percent, up to about 50 weight percent, up to about 20weight percent, and/or the like. Other possible constituents of thefirst hydrocarbon-containing oil may include aromatic compounds,polyaromatic compounds, naphthenes, and/or the like.

Nitrogen-containing organic compounds may include ammonia, amines,anilines, cyclic amines, aromatic amines, pyrrole, pyridine, indole,isoindole, quinoline, carbazole, acridine, alkyl nitrogen substitutedderivatives, and/or the like. The nitrogen-containing organic compoundsmay have any suitable concentration, such as about 0 parts per million,between about 0.1 parts per million to about 3,000 parts per million,and/or the like, expressed as elemental nitrogen.

In one embodiment, the one or more hydrocarbons in the first feedstockboil at temperatures between about 150 degrees Celsius to about 400degrees Celsius. Molecules of the first feedstock may include anysuitable number of carbon atoms, such as between about 10 to about 22.The molecules can be used in production of diesel fuel, heating oil, jetfuel, other distillate material, and/or the like.

Conditions in the first reactor can be maintained to reduce aconcentration of non-paraffinic species contained in the firstfeedstock, for example to hydrogenate olefins to paraffins, convertorganic nitrogen compounds to ammonia, convert organic sulfur compoundsto hydrogen sulfide, form other suitable volatile compounds, and/or thelike. This can be achieved by employing conditions used in refineryhydrocracking processes, hydrodenitrification processes,hydrodesulfurisation processes, and/or the like.

Aromatic compounds may additionally be present in thehydrocarbon-containing oil, such as benzenes, xylenes, toluenes, otherpolyaromatic compounds, naphthalenes, phenanthrenes, and/or the like.

Suitable reactor conditions for hydrodesulfurization,hydrodenitrification, hydrocracking, and/or the like can includetemperatures between about 250. degrees Celsius to about 430 degreesCelsius, and pressures between about 20 bars to about 200 bars on anabsolute pressure basis. A severity of the reactor conditions can dependon the nature of the hydrocarbon-containing process stream being fed tothe reactor, the nature of the desired hydrocarbon product stream,and/or the like.

For example, when removing heteroatom-containing organic compounds froma stream suitable for gasoline fuel, low severity hydrogenationconditions with temperatures between about 250 degrees Celsius to about350 degrees Celsius and pressures between about 20 bars absolute toabout 40 bars absolute can be used. When removing heteroatom-containingorganic compounds and olefins from a hydrocarbon-containing oil suitablefor diesel fuel, then moderate severity hydrotreating conditions may beemployed with temperatures between about 300 degrees Celsius to about400 degrees Celsius and pressures between about 30 bars absolute toabout 70 bars absolute. For vacuum gas oil feedstocks and otherrelatively high boiling hydrocarbon-containing oils, more severehydrotreating conditions may be employed, such as temperatures betweenabout 350 degrees Celsius, to about 410 degrees Celsius and pressuresbetween about 70 bars absolute to about 150 bars absolute. When crackingfeedstocks to produce a mixture of hydrocarbons suitable for gasolineand/or diesel fuels, higher severity, hydrocracking conditions can beemployed, such as temperatures between 350 degrees Celsius to about 430degrees Celsius and pressures in the between about 100 bars absolute toabout 200 bars absolute.

The hydrogenation reaction in the first reactor may be catalyzed oruncatalyzed. Suitable catalysts may include nickel, cobalt, molybdenum,platinum, palladium, ruthenium, rhodium, and/or the like. Optionally,catalysts can be supported on a support, such as silica, alumina,gamma-alumina, silica-alumina, titania, zirconia, carbon, activatedcarbon, zeolites and/or the like. Where the first feedstock includessulfur-containing compounds, the catalysts can be preferably selectedfrom nickel, cobalt, and/or molybdenum. Sulfur may deactivate somemetals, such as platinum, palladium, ruthenium, rhodium, and/or thelike.

In the first reactor and according to one embodiment, the firstfeedstock can be contacted with hydrogen to produce a first hydrogenatedproduct stream. Where the first feedstock includes olefins, organosulfurcompounds, organonitrogen compounds, and/or aromatic compounds, thefirst hydrogenated product stream generally can include such componentsat lower concentrations than the first feedstock. For example, olefinscan be converted to corresponding paraffinic hydrocarbons,heteroatom-containing organic compounds can be converted to hydrocarbonsand volatile heteroatom-containing compounds, aromatic compounds can beconverted into compounds with less aromatic character, cyclic alkanes,naphthenes, cyclic compounds with isolated double bonds, compounds withnonconjugated aromatic double bonds, and/or the like. Unreacted hydrogencan also form part of the first hydrogenated product stream.

In the second reactor and according to one embodiment, the secondfeedstock can include a bio-oil. The feedstock can be contacted withhydrogen to produce a second hydrogenated product stream includinghydrocarbons derived from the bio-oil. Additional components and/orcompounds may result from the hydrogenation reaction, such as lighthydrocarbons (for example, C1 to C4 alkanes), one or more oxides ofcarbon (for example, carbon monoxide (CO) and carbon dioxide (CO₂)),water, and/or the like. Unreacted hydrogen can be present in the secondhydrogenated product stream.

The second feedstock can include a bio-oil, such as a carboxylic acidand/or a carboxylic acid derivative. A derivative of a carboxylic acidcan be a compound that would yield the carboxylic acid when subjected toa hydrolysis reaction, for example. Examples of derivatives ofcarboxylic acids may include carboxylic acid esters and carboxylic acidanhydrides.

The second feedstock can include bio-oils and/or the like. The bio-oilsmay have a suitable boiling range, such as the boiling range of thehydrocarbons produced by a hydrogenation reaction in a same range asthose in the target hydrocarbon fuel. The carbon chain lengths can alsobe similar to hydrocarbons suitable for use in the target fuel. Forexample, diesel fuels may include hydrocarbons with about 10 carbonatoms to about 22 carbon atoms. Bio-oils used to produce hydrocarbonswith numbers of carbon atoms in this range can be any suitable compound,such as mono-carboxylic acids, di-carboxylic acids, n-hexadecanoic acid,1,16-di-hexadecanoic acid, and/or the like.

Fatty acids, fatty acid derivatives, and/or the like can also besuitable for feedstocks. For example fatty acids with a general formulaof R¹C(O)OH and/or esters with a general formula of R¹C(O)O—R² can befed to the reactor. R¹ and R² can be selected from hydrocarbon chains,substituted hydrocarbon chains, and/or the like. Examples of fatty acidsand/or fatty acid derivatives useful in the production of hydrocarbondiesel fuel may include lauric acid, myristic acid, palmitic acid,stearic acid, linoleic acid, oleic acid, arachidic acid, erucic acid,and/or the like. Other suitable derivatives may include compounds whereR¹ includes 11, 13, 15, 17, 17, 19 and/or 21 carbon atoms respectively.In one embodiment, the feedstock may include esters, such as in the formof monoglycerides, diglycerides, triglycerides, and/or the like. Theesters may have a general formula of [R¹C(O)O]_(n)C₃H₅(OH)_(3-n), wheren can be 1, 2, 3, and/or the like. The fatty acids and/or fatty acidderivatives may have saturated hydrocarbon groups, and/or unsaturatedhydrocarbon groups. Diglycerides and/or triglycerides may includehydrocarbon chains derived from the same and/or different fatty acids.

The bio-oils can be derived from biomass, such as fats and/or oilsderived from plants, animals, algae, other microbial organisms, and/orthe like. Full combustion use of biologically-derived bio-oils can havea lower net emission of atmospheric carbon dioxide compared to anequivalent fuel derived purely from mineral sources. Suitable biologicalsources of bio-oils may include plant-derived oils, such as rapeseedoil, peanut oil, canola oil, sunflower oil, tall oil (pine oil), cornoil, soybean oil, and/or the like. Other suitable materials may includeanimal oils and/or fats, such as tallow, lard, poultry fats, fish oilsand fish fats, blubber, substances from other marine organisms,substances from land animals, substances from other airborne animals,and/or the like. Another suitable source may include waste oils, such asused cooking oils and/or the like.

Biological oils and/or fats generally may include triglycerides withfatty hydrocarbon chains having numbers of carbon atoms commensuratewith hydrocarbons found in diesel fuel. According to one embodiment, thesecond reactor maintains conditions which enable the bio-oil to undergodecarboxylation and/or hydrodeoxygenation reactions to producehydrocarbons in a diesel fuel boiling range. The conditions within thesecond reactor can be maintained to reduce cracking reactions of thefatty acid hydrocarbon groups, such as to reduce production ofshorter-chain hydrocarbons with generally lower boiling point (lesssuitable for diesel fuel). Minimizing hydrocarbon cracking can also helpreduce hydrogen consumption and improve energy utilization and/orfeedstock efficiency.

To obtain a hydrocarbon from a bio-oil, two reaction pathways can befollowed as shown below in equations I and II with a fatty acidtriglyceride. In equation I, oxygen from the carboxylate group of thetriglyceride can be removed in the form of carbon dioxide. As a result,the product hydrocarbon, R¹H may not include a carboxyl carbon. Thereaction of equation I can be referred to as decarboxylation.

(R¹—C(O)—O)₃—C₃H₅+3H₂→3R¹H+3CO₂+C₃H₈   I

In equation II, oxygen can be removed as water, and the producthydrocarbon R¹CH₃ may include a carboxyl carbon. The reaction ofequation II can be referred to as hydrodeoxygenation.

(R¹—C(O)—O)₃—C₃H₅+12H₂→3R¹CH₃+C₃H₈+6H₂O   II

Other reactions that may occur in the reactor include reduction ofcarbon dioxide to carbon monoxide and methane, according to reactionsIII and IV.

CO₂+H₂→CO+H₂O   III

CO+3H₂→CH₄+H₂O   IV

A mixture and/or a combination of the reactions III and IV can takeplace in the second reactor.

In the production of lower boiling point fuels (such as gasoline with aboiling point range of between about 20 degrees Celsius and about 220degrees Celsius) cracking of the hydrocarbons can be advantageous. Forexample, hydrocarbon chains in fatty acids and/or fatty acid derivativesmay be longer than hydrocarbons present in gasoline. By using crackingprocesses, the long fatty acid-derived hydrocarbon chains can beconverted into shorter carbon chain hydrocarbons, such as with a lowerboiling point and can be more suitable for use as or in the productionof gasoline.

According to one embodiment, a mixture of both mineral oil andbiological oil can be supplied to the second reactor, such as to diluteand/or temper an exotherm. Optionally, additional hydrocarbons (such asa portion of the first feedstock and/or a portion of the firsthydrogenation product stream and/or a portion of the liquid phase fromthe separator) can be fed to the second reactor in addition to thesecond feedstock. Hydrogenation of bio-oils can be highly exothermic, sodiluting their concentration with less reactive hydrocarbons canmitigate temperature rises in and/or across the second reactor. Anotherway of mitigating excessive temperature rises can be to pre-saturate thesecond feedstock with hydrogen in a pre-saturator, such as to feedand/or supply a liquid phase including dissolved hydrogen to the secondreactor. Pre-saturation of hydrogen can also be used for the firstfeedstock before feeding it to the first reactor.

Conditions in the second reactor can be maintained such that the one ormore bio-oils can be converted into one or more hydrocarbons. Hydrogenconsumption by the bio-oil may be greater than that of thehydrocarbon-containing first feedstock. Temperatures between about 200degrees Celsius to about 410 degrees Celsius, between about 320 degreesCelsius to about 410 degrees Celsius, and/or the like can be maintainedin the second reactor. Pressures between about 1 bar absolute to about200 bars absolute, between about 10 bars absolute to about 150 barsabsolute, and/or the like can be maintained in the second reactor.

Conditions can be maintained in the second reactor such that almostcomplete conversion of the bio-oil can be achieved, such as greater thanabout 90 weight percent conversion, greater than about 95 weightpercent, and/or the like. The reaction in the second reactor can becatalyzed, such as by a suitable catalyst discussed above.

The first hydrogenated product stream and second hydrogenated productstream can be fed to a separator, in which volatile products can beremoved as a vapor phase and liquid hydrocarbons can be separated as aliquid phase. The liquid phase hydrocarbons can be used as and/or in theproduction of a liquid hydrocarbon fuel. Optionally and/oralternatively, the liquid phase hydrocarbons can be further separatedinto two or more different fractions, such as based on boiling point.Each fraction can be used as and/or in the production of separate liquidhydrocarbon fuels. The liquid phase hydrocarbons may be processed by oneor more additional steps.

Separation of vapor and liquid phase components can be achieved usingdistillation, such as with a distillation tower, a fractionation column,and/or the like. The vapor phase components can be removed from the topof the column, while one or more liquid phase hydrocarbon fractions canbe removed from different levels within the column. Optionally and/oralternatively, flash separation vessels and/or drums can be used insteadof and/or in addition to distillation columns (multiple theoreticalstages). The flash drums can be used where a proportion of volatilecomponents to liquid components may be high and/or where no separationof the liquid phase hydrocarbons into two or more fractions may bedesired. Flash separation can be carried out before productdistillation.

The vapor phase removed from the separator can be recycled to the firstreactor and/or the second reactor. A purge stream can be removed fromthe vapor phase before recycle to prevent a build up of contaminants,such as hydrogen sulfide, carbon monoxide, carbon dioxide, ammonia,methane, ethane, propane, other nitrogen compounds, other sulfurcompounds, and/or the like. The contaminants may affect reactions rates,act as catalyst poisons, and/or form relatively inert components(diluents) that can act as a diluent.

According to one embodiment, hydrogen in the vapor phase from theseparator can be recycled only to the first reactor, such as to preventimpurities like sulfur-containing compounds present in the vaporfraction from the separator from contacting the catalyst in the secondreactor. This configuration enables catalysts that may be prone todeactivation in the presence of impurities (sulfur) to be used therein.Suitable catalysts may include platinum, palladium, ruthenium, rhodium,and/or the like.

The liquid phase from the separator can be low in sulfur content and/ornitrogen content. The sulfur content may be below about 500 parts permillion, below about 50 parts per million, and/or the like, expressed aselemental sulfur.

The separator may, but not necessarily, operate at a pressure less thanthat of the first reactor and/or the second reactor. According to oneembodiment, use of a common separator for treating the first and secondhydrogenated process streams can be advantageous, because a separatetreatment unit for converting feedstocks including bio-oils can beretrofitted to existing fuel production units (refineries). Thisconfiguration can also use existing infrastructure for treatments and/orprocesses, such as purification and/or separation. This configurationcan provide improved energy integration and also enable existingcompressors to be used, for example in hydrogen recycle.

Another advantage of this configuration can be the production of dieselfuel including components derived from biological sources. Hydrocarbonsproduced from the biological oil may tend to be linear paraffins, whichcan have poor cold flow characteristics. Paraffins can be isomerised andused as a diesel fuel. By mixing the biological hydrocarbons withexisting conventionally derived diesel components, the impact of thebiologically-derived linear paraffins can be minimized. Dieselcomponents may be derived from catalytic crackers, visbreakers, cokers,and/or the like. These diesel components can include branched alkanesand aromatic components with good cold flow characteristics.

Optionally and/or alternatively, isomerization reactions can be carriedout on any one or more of the first and/or second hydrogenated productstreams, the liquid phase removed from the separator, any liquidhydrocarbon fuels, other suitable fractions, and/or the like.Isomerization may be conducted in the presence of hydrogen and in thepresence of a catalyst. Isomerized hydrocarbons can be produced in thesecond reactor by suitable selection of catalyst and process conditions.

According to one embodiment, operating hydrogenation reactions inseparate reactors can allow different conditions for hydrogenating eachof the feedstocks, such as to optimize reaction conditions, improveproduct yields, and/or the like. The second reactor, may have a lowervolume of feedstock to hydrogenate, so the second reactor can be smallerthan the first reactor. For example, where a liquid hydrocarbon fuel has5 weight percent and/or volume of its hydrocarbons derived from abiological oil, then the second reactor used to hydrogenate thebiological oil can be about 5 percent of a size of the first reactor.The smaller reactor can be less expensive to construct and energyintensive to operate than a larger reactor.

The liquid phase removed from the separator and/or the liquidhydrocarbon fractions separated in the separator, may include betweenabout 0.1 weight percent to about 49.9 weight percent, between about 2weight percent to about 15 weight percent, and/or the like ofhydrocarbons derived from the second hydrogenated product stream.Hydrocarbons derived from the first hydrogenated product stream can forma majority in the liquid phase hydrocarbons removed from the separatorand/or in the final liquid fuel hydrocarbons.

FIG. 1 schematically shows a hydrotreating unit 10, according to oneembodiment. The hydrotreating unit 10 receives a mineral oil basedhydrocarbon stream 14 and a biological oil based hydrocarbon stream 16.The mineral oil based hydrocarbon stream 14 connects and/or passes to afirst reactor 20 to form a first hydrotreated product stream 26. Thebiological oil based hydrocarbon stream 16 connects and/or passes to asecond reactor 22 to form a second hydrotreated product stream 28. Thehydrotreating unit 10 includes a hydrogen recycle system 30 to formand/or separate a product stream 24, a recycle hydrogen stream 36, and apurge stream 40 withdrawn from the combined first hydrotreated productstream 26 and the second hydrotreated product steam 28. The hydrogenrecycle system 30 can include a suitable gas separation apparatus and acompressor, for example. Optionally, the recycle hydrogen stream 36 canconnect and/or pass to a carbon dioxide removal system 42 and formand/or separate a carbon dioxide steam 44. Hydrogen streams 32 to thefirst reactor 20 and the second reactor 22 come from a common hydrogenstream 38 connected to both a make-up hydrogen stream 34 and the recyclehydrogen stream 36.

FIG. 2 schematically shows a hydrotreating unit 10, according to oneembodiment. The hydrotreating unit 10 receives a mineral oil basedhydrocarbon stream 14 and a biological oil based hydrocarbon stream 16.The mineral oil based hydrocarbon stream 14 connects and/or passes to afirst reactor 20 to form a first hydrotreated product stream 26. Thebiological oil based hydrocarbon stream 16 connects and/or passes to asecond reactor 22 to form a second hydrotreated product stream 28. Thehydrotreating unit 10 includes a hydrogen recycle system 30 to formand/or separate a product stream 24, a recycle hydrogen stream 36, and apurge stream 40 withdrawn from the combined first hydrotreated productstream 26 and the second hydrotreated product steam 28. Optionally, therecycle hydrogen stream 36 can connect and/or pass to a carbon dioxideremoval system 42 and form and/or separate a carbon dioxide steam 44.The recycle hydrogen stream 36 connects and/or passes to the firstreactor 20. A make-up hydrogen stream 34 connects and/or passes to thesecond reactor 22.

FIG. 3 schematically shows a hydrotreating unit 10, according to oneembodiment. The hydrotreating unit 10 receives a mineral oil basedhydrocarbon stream 14 and a biological oil based hydrocarbon stream 16.The mineral oil based hydrocarbon stream 14 connects and/or passes to afirst reactor 20 to form a first hydrotreated product stream 26. Thebiological oil based hydrocarbon stream 16 connects and/or passes to asecond reactor 22 to form a second hydrotreated product stream 28. Thehydrotreating unit 10 includes a hydrogen recycle system 30 to formand/or separate a product stream 24, a recycle hydrogen stream 36, and apurge stream 40 withdrawn from the combined first hydrotreated productstream 26 and the second hydrotreated product steam 28. Optionally, therecycle hydrogen stream 36 can connect to a carbon dioxide removalsystem 42 and form and/or separate a carbon dioxide steam 44. Therecycle hydrogen stream 36 connects and/or passes to the second reactor22. A make-up hydrogen stream 34 connects and/or passes to the firstreactor 20.

FIG. 4 schematically shows a hydrotreating unit 10, according to oneembodiment. The hydrotreating unit 10 includes a feed stream 12connected to a hydrotreating reactor 18 to form a reactor effluent. Thehydrotreating unit 10 includes a hydrogen recycle system 30 to formand/or separate a product stream 24, a recycle hydrogen stream 36 and apurge stream 40 withdrawn from the reactor effluent. A hydrogen stream32 includes both a make-up hydrogen stream 34 and the recycle hydrogenstream 36. Optionally, the recycle hydrogen stream 36 can connect and/orpass to a carbon oxide removal system 46 and form and/or separate acarbon oxide steam 48.

FIG. 5 schematically shows a carbon oxide removal system 46, accordingto one embodiment. The carbon oxide removal system 46 connects and/orpasses a recycle hydrogen stream 36 to a water-gas shift reactor 52 (forconverting carbon monoxide to carbon dioxide) followed by an absorptionsystem 50 (for removing carbon dioxide), and optionally followed by amethanation reactor 54 (for removing and/or reducing remaining carbonoxides). The absorption system 50 may include an absorber column and/ortower and a stripper column and/or tower with a single flow of solventand/or solution. A carbon dioxide vent and/or purge stream can leaveand/or flow from a top of the stripper tower. Configurations of theabsorption system 50 with multiple flows (such as lean flows andsemi-lean flows, not shown) are within the scope of this invention. Themethanation reactor 54 includes a cleaned up recycle hydrogen streamand/or line. In the alternative, the carbon oxide removal system 46 mayexclude a water-gas shift reactor 52 and/or an absorption system 50, andinclude a methanation reactor 54.

FIG. 6 schematically shows a hydrotreating reactor 18, according to oneembodiment. The hydrotreating reactor 18 with connects and/or passes afeed stream 12 to form a product stream 24. The hydrotreating reactor 18includes a multiple bed reactor 56 with individual beds A, B, and C, forexample. Preferably the individual beds have a generally seriesconfiguration. Parallel configurations and/or series-parallelcombinations are within the scope of this invention. The multiple bedreactor 58 can use a single pressure shell as shown and/or include morethan one pressure shells and/or vessels. The hydrotreating reactor 18includes interbed (between) purges 58 and optionally bed hydrogensupplies 60. The interbed purges 58 connect to and/or constitute a partof a hydrogen recycle system 30 to form and/or separate a recyclehydrogen stream 36 and a purge stream 40. A hydrogen stream 32 includesboth a make-up hydrogen stream 34 and the recycle hydrogen stream 36.Optionally, the recycle hydrogen stream 36 can connect and/or pass to acarbon oxide removal system 46 and form and/or separate a carbon oxidesteam 48.

FIG. 7 schematically shows a hydrotreating reactor 18, according to oneembodiment. The hydrotreating reactor 18 with connects and/or passes afeed stream 12 to form a product stream 24. The hydrotreating reactor 18includes a fluidized bed reactor 62 and a regenerator 64. Theregenerator 64 connects and/or passed to the fluidized bed reactor 62 bya coked catalyst stream 68 (send line) and a decoked catalyst stream 70(return line). The regenerator 64 connects and/or passes to aregenerating material stream 66, such as for removing coke by hydrogen,oxygen, water, steam, and/or the like. A hydrogen stream 32 includesboth a make-up hydrogen stream 34 and a recycle hydrogen stream 36.Optionally, the recycle hydrogen stream 36 can connect and/or pass to acarbon oxide removal system 46 and form and/or separate a carbon oxidesteam 48.

According to one embodiment, the invention can include a method and/or aprocess of hydrotreating hydrocarbons. The method can include the stepof feeding a mineral oil based hydrocarbon stream to a hydrotreatingunit under hydrotreating conditions and with a hydrotreating catalyst toform a hydrotreated product stream, and the step of measuring a sulfurcontent of the hydrotreated product stream. The method can also includethe step of starting co-feed of a biological oil based hydrocarbonstream to the hydrotreating unit, and the step of measuring the sulfurcontent of the hydrotreated product stream during co-feed. The methodcan also include the step of stopping co-feed of the biological oilbased hydrocarbon stream upon the sulfur content of the hydrotreatedproduct stream reaching a predetermined value, and the step of measuringthe sulfur content of the hydrotreated product stream after stoppingco-feed. Upon termination of the co-feed, the sulfur content of thehydrotreated product stream returns to a value of close to (about)before the co-feed of the sulfur content of the hydrotreater effluentafter the step of stopping co-feed.

Hydrotreating broadly refers to processes and/or steps to remove and/orreduce impurities or heteroatoms from a molecule and/or a compound, suchas by reaction with one or more hydrogen atoms. Hydrotreating can removeand/or reduce sulfur content (hydrodesulfurization), nitrogen content(hydrodenitrogenation), oxygen content (hydodeoxygenation), aromaticcontent (hydrodearomatization), metal content (hydrodemetalization),double bonds (saturation or hydrogenation), triple bonds (saturation orhydrogenation), and/or the like. Hydrotreating can also includeprocesses known as hydrofining, hydrofinishing, hydrocracking, and/orthe like.

Hydrocarbon broadly refers to any suitable compound containingpredominantly and/or mostly carbon and hydrogen, such as may be derivedfrom renewable and/or nonrenewable resources. Sources of hydrocarbonsmay include, but are not limited to, crude oil, petroleum, natural gas,coal, peat, tar sands, shale, bitumen, synthetic processes, plants,animals, fungi, yeasts, microorganisms, and/or the like.

Feeding broadly refers to moving, pumping, spraying, sparging,supplying, and/or the like.

Stream broadly refers to a flow, a quantity, a volume, a mass, and/orthe like.

Unit broadly refers to devices and/or apparatuses, such as used toaffect a change and/or accomplish a task.

Mineral oil based broadly refers to materials and/or substances derivedat least in part from the Earth, such as fossil fuels. Mineral oil maycome from any suitable source, such as natural gas, crude oil,petroleum, coal, peat, shale, tar sands, bitumen, other geologicformations, and/or the like. According to one embodiment, mineral oilbased excludes living and/or recently living organisms.

Hydrotreating unit broadly refers to suitable devices and/or apparatusesused in hydrotreating a stream and/or a material, such as pumps,compressors, pipes, valves, reactors, vessels, furnaces, heatexchangers, distillation columns, separators, control systems, and/orthe like. According to one embodiment, the hydrotreating unit includes atrickle bed reactor, or a fluidized bed reactor.

Hydrotreating conditions broadly refer to any suitable conditions orphysical circumstances for carrying out a hydrotreating reaction.Hydrotreating conditions may include a pressure of between aboutatmospheric and about 2000 bars, and/or the like. Hydrotreatingconditions may include a temperature of between about 100 degreesCelsius and about 1,000 degrees Celsius, at least about 275 degreesCelsius, and/or the like. Hydrotreating conditions may include and/orexclude a catalytic material.

Hydrotreating catalysts broadly refer to any suitable substance and/ormaterial to increase a rate of a hydrotreating reaction. Catalysts canbe supported and/or unsupported. Catalysts can be in any suitable sizeand/or shape, such as powders, granules, pellets, engineered shapes,and/or the like. Generally, but not necessarily, catalysts can be basedon one or more metals and/or metal compounds, such as cobalt,molybdenum, nickel, iron, platinum, palladium, ruthenium, rhenium, othertransition metals, other precious metals, and/or the like.

Product broadly refers to a material and/or a substance that hasundergone at least a partial change and/or transformation, such as froma separation and/or a reaction.

Measuring broadly refers to quantifying, analyzing, appraising,determining a content of, and/or the like. Any suitable analyticaland/or laboratory techniques may be use for measuring, such asspectroscopy, x-ray fluorescence, gas chromatography, liquidchromatography, mass spectroscopy, calorimetry, titration, and/or thelike. Any suitable molecule and/or compound can be measured, such assulfur, oxygen, nitrogen, metals, and/or the like. Measuring can be doneat any suitable frequency and/or time interval, such as generallycontinuously, about once per second, about once per minute, about onceper hour, about three times a day, about two times per day, about onetime per day, about once for every other day, about once per week,and/or the like.

Sulfur in a product stream broadly refers to both elemental sulfur andsulfur species in other forms, such as thiophenes, disulfides, thiols,mercaptans, sulfur oxides, hydrogen sulfide, higher molecular weightcompounds, and/or the like. The sulfur may include any suitable amount,such as between about 0.01 parts per million and about 1,000 parts permillion, less than about 500 parts per million, less than about 100parts per million, less than about 50 parts per million, less than about10 parts per million, less than about 5 parts per million, less thanabout 1 part per million, and/or the like on a mass basis.

Starting broadly refers to beginning and/or commencing a step and/or anoperation.

Co-feed broadly refers to feeding at substantially the same time and/orconditions as a first item, stream, and/or component.

Biological oil based broadly refers to materials and/or substancesderived at least in part from living and/or recently living organismsand/or processes, such as from plants, animals, vertebrates,invertebrates, microorganisms, algae, yeast, fungi, bacteria,cyanobacteria, and/or the like. Biological oil production and/or growthcan include fixation of atmospheric carbon dioxide throughphotosynthesis, associated biochemical processes, and/or the like.According to one embodiment, biological oil can be derived fromnaturally occurring organisms and/or genetically modified organisms.Suitable sources of biological oil may include palm oil, olive oil,rapeseed oil, soybean oil, coconut oil, corn oil, jatropha oil, tallow(animal fat, such as beef, chicken, pork, and/or the like), and/or thelike. Biological oil based streams and/or materials may include sulfurcompounds, nitrogen compounds, oxygen compounds, and/or the like.According to one embodiment, biological oil based excludes fossilizedmaterials.

According to one embodiment, the biological oil based hydrocarbon streamcan include fatty acids, pyrolysis oils, liquefaction oils, acylglycerides, and/or the like. Acyl glycerides can include monoglycerides,diglycerides, trigylcerides, and/or the like.

Stopping broadly refers to ending and/or halting a step and/or anoperation.

Predetermined broadly refers to arrived at beforehand and/or ahead oftime, such as before the current step. The predetermined level orthreshold level can be any suitable amount and/or level, such as basedon product specifications, blending stock availability, and/or the like.The predetermined value may include between about 0.1 parts per millionand about 10,000 parts per million, between about 1 part per million andabout 1,000 parts per million, less than about 500 parts per million,less than about 100 parts per million, less than about 50 parts permillion, less than about 10 parts per million, and/or the like on a massbasis.

Close to broadly refers to any suitable number and/or range around aninitial and/or target value, such as a value of plus or minus about1,000 parts per million, plus or minus about 500 parts per million, plusor minus about 100 parts per million, plus or minus about 50 parts permillion, plus or minus about 20 parts per million, plus or minus about10 parts per million, plus or minus about 5 parts per million, and/orthe like on a mass basis.

According to one embodiment, a value of close to can include betweenabout 30 percent and about 300 percent, between about 50 percent andabout 150 percent, between about 80 percent and about 120 percent,between about 90 percent and about 110 percent of an initial value, suchas the sulfur content of before the starting co-feed.

A ratio of time with the co-feed to the hydrotreating unit to timewithout the co-feed may include any suitable amount, such as betweenabout 0.01 to about 100, between about 0.2 to about 5, between about 0.4to about 2.5, and/or the like.

A duration and/or a period of coprocessing (campaign) may be for anysuitable length of time, such as at least about 8 hours, at least about1 day, at least about 2 days, at least about 5 days, at least about 7days, at least about 10 days, at least about 14 days, at least about 21days, at least about 30 days, at least about 1 month, at least about 3months, and/or the like.

The biological oil based hydrocarbon stream may form any suitable amountof a feed to the hydrotreating unit, such as between about 0 weightpercent and about 100 weight percent, between about 0.1 weight percentand about 80 weight percent, between about 1 weight percent and about 50weight percent, about 30 weight percent, about 5 weight percent, and/orthe like of a feed to the hydrotreating unit. According to oneembodiment, the mineral oil based hydrocarbon stream stops duringco-feed. According to one embodiment, the biological oil basedhydrocarbon stream does not stop, but an amount and/or a flow can bevaried.

Embodiments with the main feed being biological oil based hydrocarbonstreams and the co-feed being mineral oil based hydrocarbon streams arewithin the scope of this invention.

The method can include any suitable rate of initial increase in sulfurcontent of the hydrotreated product, such as the initial increase has aslope of between about 2 times and about 12 times greater than a slopeof the continuing increase, and/or the like. Embodiments with where theco-feed causes no increase in sulfur content of the product are withinthe scope of this invention. Similarly, embodiments with where theco-feed reduces sulfur content of the product are within the scope ofthis invention.

The method may include the steps recited above in the order and/orfrequency recited above, such as in a sequence and/or a progression ofsteps, according to one embodiment. In the alternative, the steps may bereordered and/or repeated as beneficially desired.

According to one embodiment, the invention can include a hydrotreatingunit for processing mineral oil based hydrocarbon streams, biologicaloil based hydrocarbon streams, and/or the like. The unit can include afirst hydrotreating reactor for receiving a mineral oil basedhydrocarbon stream and forming a first hydrotreated product stream, anda second hydrotreating reactor for receiving a biological oil basedhydrocarbon stream and forming a second hydrotreated product stream.This configuration can form a parallel processing arrangement, such as aseparate train and/or reactor system for mineral oil based hydrocarbonstreams from biological oil based hydrocarbon streams.

Other combinations of series and/or parallel hydrotreating reactors arewithin the scope of this invention, such as a first reactor(hydrodesulfurization) on mineral oil in series with a second reactor(deoxygenation) on bio-oil diluted with a first reactor effluent.Make-up hydrogen could be added to the first reactor and/or the secondreactor. Purging and/or scrubbing can be done after the first reactor(between) and/or after the second reactor depending upon theconfiguration, catalyst choices for the reactors, and/or the like.

Reactor broadly refers to a vessel, an apparatus and/or the like for atleast one chemical reaction to take place within, such as uponcontacting with a catalyst. The reactor may include any suitableconfiguration, such as a packed bed, multiple beds, a trickle bed, anupflow reactor, a downflow reactor, a fluidized bed reactor, and/or thelike.

According to one embodiment, a common hydrogen stream supplies both thefirst hydrotreating reactor and the second hydrotreating reactor, andthe hydrogen stream includes make-up (fresh) hydrogen and recycle (used)hydrogen. This configuration offers parallel processing of thehydrocarbon streams but a single hydrogen system.

A ratio of the make-up hydrogen to the recycle hydrogen can include anysuitable value and/or amount, such as between about 1 to 100, betweenabout 100 to 1, about 1:10, and/or the like on a mass basis, a molebasis, and/or a volume basis.

According to one embodiment, a make-up (fresh) hydrogen stream connectsto the second hydrotreating reactor (biological oil based) and a recycle(used) hydrogen stream connects to the first hydrotreating reactor(mineral oil based). This configuration allows processing of thebiological oil based hydrocarbon steam with make-up hydrogen, such aswithout carbon oxide impurities, sulfur impurities, and/or the like.

According to one embodiment, a make-up (fresh) hydrogen stream connectsto the first hydrotreating reactor (mineral oil based) and a recycle(used) hydrogen stream connects to the second hydrotreating reactor(biological oil based). This configuration allows processing the mineraloil based hydrocarbon stream with make-up hydrogen, such as withoutcarbon oxide impurities, water, and/or the like.

Other combinations of hydrogen configurations and reactors are withinthe scope of this invention.

According to one embodiment, the first hydrotreating reactor may includea cobalt and molybdenum catalyst and the second hydrotreating reactormay include a nickel and molybdenum catalyst. Other combinations ofdifferent types of catalysts and reactors are within the scope of thisinvention. This configuration allows optimizing catalyst for eachservice and/or duty that is it in.

According to one embodiment, the unit can include a carbon dioxideremoval system on a hydrogen recycle stream. The carbon dioxide removalsystem may remove and/or reduce an amount of carbon dioxide in thehydrogen recycle stream. The carbon dioxide may be formed from theprocessing of the biological oil based hydrocarbon stream with oxygencontaining species and/or compounds. The carbon dioxide removal systemmay include any suitable device and/or apparatus, such as absorptionsystems, adsorption systems, solvent systems, reactive solutions (hotpotassium carbonate, for example), and/or the like. The carbon dioxideremoval system can remove any suitable amount of carbon dioxide in thehydrogen recycle stream before the removal system, such as at leastabout 1 percent, at least about 30 percent, at least about 70 percent,at least about 90 percent, at least about 95 percent, and/or the like ona volume basis and/or a mole basis.

According to one embodiment, the invention may include a method ofhydrotreating hydrocarbons. The method may include the step of feeding amineral oil based hydrocarbon stream to a hydrotreating unit underhydrotreating conditions in the presence of a hydrotreating catalyst toform a hydrotreated product stream. The method may also include the stepof measuring a sulfur content of the hydrotreated product stream, andthe step of starting co-feed of a biological oil based hydrocarbonstream to the hydrotreating unit. The method may also include the stepof measuring the sulfur content of the hydrotreated product streamduring co-feed, and the step of stopping co-feed of the biological oilbased hydrocarbon stream upon the sulfur content of the hydrotreatedproduct stream reaching a predetermined value to effect a reduction insulfur content of the hydortreated product stream such that the sulfurcontent returns to a value close to the value prior to terminating theco-feed.

The scope of this invention also includes methods of operating ahydrotreating unit with a first hydrotreating reactor and a secondhydrotreating reactor.

According to one embodiment, this invention can include a hydrotreatingunit for processing mineral oil based hydrocarbon streams, biologicaloil based hydrocarbon streams, and/or the like. The unit can include ahydrotreating reactor for receiving a feed stream and forming ahydrotreated product stream, and a hydrogen recycle system forseparating and returning unconverted hydrogen to the hydrotreatingreactor as a hydrogen recycle stream. The unit can include a carbonoxide removal system for removing at least a portion of carbon oxidesfrom the hydrogen recycle stream.

Carbon oxides broadly refer to compounds and/or substances containingprimarily carbon and oxygen, such as carbon monoxide, carbon dioxide,and/or the like. Carbon oxides may be generated, formed, and/or releasedfrom the processing of biological oil based hydrocarbon streams, such asmay contain oxygen. Without being bound by theory of operation, carbonoxides may slow down and/or inhibit hydrotreating reactions, such as mayallow an increase in product sulfur content (slip).

The carbon oxide removal system may include any suitable device and/orapparatus, such as to reduce and/or remove at least a partial carbonoxide content of a hydrogen recycle stream. Carbon oxide removal systemsmay use reactions, separations, other unit operations, and/or the like.

According to one embodiment, the carbon oxide removal system may includea carbon dioxide absorption system, such as a caustic scrubber, a waterscrubber, an amine scrubber, a solvent based contactor, a potassiumcarbonate absorber, a pressure swing adsorption vessel, a temperatureswing adsorption vessel, a membrane containing vessel, a carbonate trap,a cold trap, and/or the like.

Additionally and/or alternatively, the carbon oxide removal system mayinclude a water-gas shift reactor, such as to convert carbon monoxide tocarbon dioxide. Water-gas shift reactors may include a suitable catalystand can operate at any suitable temperature, such as high temperatureshift converters, low temperature shift converters, and/or the like.

Additionally and/or alternatively, the carbon oxide removal system mayinclude a methanation reactor, such as to convert carbon oxides tomethane with hydrogen.

According to one embodiment, the hydrotreating reactor may include morethan one catalyst bed with an interbed purge for each bed each, such asto purge and/or remove at least a portion of carbon oxides in theeffluent streams from each bed. The interbed purge can be in fluidcommunication with the carbon oxide removal system. A separate hydrogenstream may be supplied to each bed of the hydrotreating reactor. Theseparate hydrogen stream may include make-up hydrogen, recycle hydrogen,and/or the like.

According to one embodiment, the hydrotreating reactor may include afluidized bed reactor and/or an ebullated bed reactor. The fluidized bedreactor may be up flow and/or down flow. Desirably, the fluidized bedreactor may include a regenerator, such as for decoking catalyst fromthe fluidized reactor. The regenerator may operate in any suitable modeand/or manner. The regenerator may decoke the catalyst with any suitablemethod and/or equipment, such as decoking with hydrogen addition, oxygenaddition, steam addition, and/or the like.

According to one embodiment, managing loss of catalyst activity caninclude campaigning different feedstocks during operation of thecatalyst for optimization of commercial performance of a unit.Essentially, reverting back to mineral oil feed can provide recovery oflost performance. FIG. 8 shows schematically the potential benefit ofcampaigning natural oil or fat coprocessing over continuous operation.The x-axis represents time and the y-axis represents sulfur values inthe product. The campaigning of bio-oil produces an elongated run with asaw toothed sulfur curve instead of continued elevation of sulfur levels(shown as extended sloped lines). In FIG. 8, letter A represents amanaged deactivation limit and/or a predetermined sulfur value in theproduct. Letter B represents an initial inhibition, such as increasedsulfur value with coprocessing of bio-oil. Regions I, III, and Vcorrespond to periods of operation on mineral and/or petroleum feed (nobio-oil). Regions II, IV, and VI correspond to periods of operation withbio-oil coprocessing. Any suitable number of cycles of operation arewithin the scope of this invention.

EXAMPLES Example 1

An experiment was conducted in a pilot plant hydrotreater by co-feeding30 weight percent tallow and 30 weight percent octanol in a light gasoil feed over a presulfided cobalt molybdenum catalyst on an aluminasupport. The pressure was 30 bars and the temperature was 343 degreesCelsius. The reactor operated with a liquid hourly space velocity of 2.

Days 1 to 10 of operation were used to line out the system on light gasoil. Days 10 to 20 were stable operation on the light gas oil. Days 20to 30 were operated on 70 weight percent light gas oil and 30 weightpercent tallow. Days 30 to 40 were operated on light gas oil. Days 40 to50 were operated on 70 weight percent light gas oil and 30 weightpercent octanol. Days 50 to 60 were operated on light gas oil.

Sulfur concentrations were measured for the liquid product as shown inFIG. 9. FIG. 9 shows time in days on the x-axis and sulfur content inthe liquid product in parts per million on a mass basis on the y-axis.FIG. 9 shows that after the initial line out (days 1 to 10), there wasstable operation and sulfur removal performance (days 10 to 20), untilthe tallow feed (days 20 to 30). With the commencement of the tallowfeed, there occurred a step change deterioration in the performance ofthe catalyst (increased sulfur content), followed by a continued loss ofdesulfurization performance. FIG. 9 also shows that upon stopping thetallow co-feed (days 30 to 40), the product sulfur level returned to orclose to prior levels. Octanol feed (days 40 to 50) did not produce asmuch of an increase in product sulfur content as did the tallow. Uponreturn to light gas oil feed (days 50 to 60), the sulfur contentremained low and stable.

Example 2

Another experiment was performed with rape seed oil to show the effectrape seed oil on the inhibition of the desulfurization process. Theexperiment was similar to Example 1 except the temperature was 363degrees Celsius. The addition of rape seed oil had a similar effect aswith tallow on product sulfur content. There was initially a stepdecrease in the performance of the cobalt molybdenum catalyst for sulfurremoval followed by a continual loss of performance with furtherexposure to the natural oil or fat. When the rape seed oil was removedfrom the feed the performance returned to the level before the exposure,as shown in FIG. 10. FIG. 10 shows time in days on the x-axis and sulfurcontent in the liquid product in parts per million on a mass basis onthe y-axis. Days 5 to 15 correspond to a period of 30 weight percentrapeseed oil coprocessing.

Example 3

In another set of experiments the effect of the level of rape seed oilon the inhibition of the desulfurization process was explored. As shownin FIGS. 11, 12, and 13, it was observed that that the different levelsof rape seed oil had similar effects on the initial increase ofhydrodesulfurization inhibition, but the rate of at which inhibitioncontinues to increase is proportional to rape seed oil content. FIG. 11shows time in days on the x-axis and a ratio of sulfur content in theproduct with the rape seed oil to sulfur content in the product with thelight gas oil for 7.5 weight percent rape seed oil (A), 15 weightpercent rape seed oil (B), and 30 weight percent rape seed oil (C). Days5 to 15 correspond to a period of rapeseed oil coprocessing.

Doubling the pressure to 60 bars with 7.5 weight percent rape seed oil(not shown) produced essentially and/or substantially the same resultsas the 7.5 weight percent rape seed oil at 30 bars (A). FIG. 12 showsrape seed oil content on the x-axis and initial inhibition (ratio ofsulfur content in products of FIG. 11) on the y-axis. FIG. 13 shows rapeseed oil content on the x-axis and continued inhibition (ratio of sulfurcontent in products of FIG. 11) on the y-axis. In all cases, when thefeed was reverted to a base petroleum feedstock, the catalystperformance recovered.

While the specification has been drafted in terms of mineral based oilhydrocarbon streams and biological oil based hydrocarbon streams, aperson of skill in the art readily appreciates that the methods andapparatuses disclosed herein may have utility regarding other processingapplications and/or materials, such as hydrotreating chemicalintermediates with heteroatoms, synthetic materials, and/or the like.

As used herein the terms “having”, “comprising”, and “including” areopen and inclusive expressions. Alternately, the term “consisting” is aclosed and exclusive expression. Should any ambiguity exist inconstruing any term in the claims or the specification, the intent ofthe drafter is toward open and inclusive expressions.

Regarding an order, number, sequence, and/or limit of repetition forsteps in a method or process, the drafter intends no implied order,number, sequence and/or limit of repetition for the steps to the scopeof the invention, unless explicitly provided.

Regarding ranges, ranges are to be construed as including all pointsbetween the upper and lower values, such as to provide support for allpossible ranges contained between the upper and lower values includingranges with no upper bound and/or lower bound.

It will be apparent to those skilled in the art that variousmodifications and variations can be made in the disclosed structures andmethods without departing from the scope or spirit of the invention.Particularly, descriptions of any one embodiment can be freely combinedwith descriptions or other embodiments to result in combinations and/orvariations of two or more elements or limitations. Other embodiments ofthe invention will be apparent to those skilled in the art fromconsideration of the specification and practice of the inventiondisclosed herein. It is intended that the specification and examples beconsidered exemplary only, with a true scope and spirit of the inventionbeing indicated by the following claims.

1. A method of hydrotreating hydrocarbons; the method comprising:feeding a mineral oil based hydrocarbon stream to a hydrotreating unitunder hydrotreating conditions and with a hydrotreating catalyst to forma hydrotreated product stream; measuring a sulfur content of thehydrotreated product stream; starting co-feed of a biological oil basedhydrocarbon stream to the hydrotreating unit; measuring the sulfurcontent of the hydrotreated product stream during co-feed; stoppingco-feed of the biological oil based hydrocarbon stream upon the sulfurcontent of the hydrotreated product stream reaching a predeterminedvalue; and measuring the sulfur content of the hydrotreated productstream after stopping co-feed; wherein the sulfur content of thehydrotreated product stream returns to a value of close to before theco-feed after the step of stopping co-feed.
 2. The method of claim 1,wherein a value of close to comprises between about 50 percent and about150 percent of the sulfur content of before the starting co-feed
 3. Themethod of claim 1, wherein the biological oil based hydrocarbon streamcomprises material derived from plants, animals, microorganisms, algae,yeast, fungi, or combinations thereof
 4. The method of claim 1, whereinthe biological oil based hydrocarbon stream comprises fatty acids,pyrolysis oils, liquefaction oils, acyl glycerides, or combinationsthereof, the acyl glycerides comprise monoglycerides, diglycerides,trigylcerides, or combinations thereof.
 5. The method of claim 1,wherein the hydrotreating catalyst comprises cobalt and molybdenum basedcatalyst.
 6. The method of claim 1, wherein the predetermined valuecomprises between about 1 part per million and about 500 parts permillion of sulfur on a mass basis.
 7. The method of claim 1, wherein aratio of time with the co-feed to the hydrotreating unit to time withoutthe co-feed comprises between about 0.01 to about
 100. 8. The method ofclaim 1, wherein the biological oil based hydrocarbon stream comprisesbetween about 1 weight percent and about 50 weight percent of a feed tothe hydrotreating unit.
 9. A hydrotreating unit for processing mineraloil based hydrocarbon streams, biological oil based hydrocarbon streams,and combinations thereof, the unit comprising: a first hydrotreatingreactor for receiving a mineral oil based hydrocarbon stream and forminga first hydrotreated product stream; and a second hydrotreating reactorfor receiving a biological oil based hydrocarbon stream and forming asecond hydrotreated product stream.
 10. The unit of claim 9, wherein acommon hydrogen stream supplies both the first hydrotreating reactor andthe second hydrotreating reactor, and the hydrogen stream comprisesmake-up hydrogen and recycle hydrogen.
 11. The unit of claim 9, whereina make-up hydrogen stream connects to the second hydrotreating reactorand a recycle hydrogen stream connects to the first hydrotreatingreactor.
 12. The unit of claim 9, wherein a make-up hydrogen streamconnects to the first hydrotreating reactor and a recycle hydrogenstream connects to the second hydrotreating reactor.
 13. The unit ofclaim 9, wherein the first hydrotreating reactor comprises a cobalt andmolybdenum catalyst, and the second hydrotreating reactor comprises anickel and molybdenum catalyst.
 14. The unit of claim 9, furthercomprising a carbon dioxide removal system on a hydrogen recycle stream.15. A hydrotreating unit for processing mineral oil based hydrocarbonstreams, biological oil based hydrocarbon streams, or combinationsthereof, the unit comprising: a hydrotreating reactor for receiving afeed stream and forming a hydrotreated product stream; a hydrogenrecycle system for separating and returning unconverted hydrogen to thehydrotreating reactor as a hydrogen recycle stream; and a carbon oxideremoval system for removing at least a portion of carbon oxides from thehydrogen recycle stream.
 16. The unit of claim 15, wherein the carbonoxide removal system comprises a carbon dioxide absorption system. 17.The unit of claim 15, wherein the carbon dioxide absorption systemcomprises a caustic scrubber, an amine scrubber, a solvent basedcontactor, a potassium carbonate absorber, a pressure swing adsorptionvessel, a temperature swing adsorption vessel, a membrane containingvessel, a carbonate trap, a cold trap, or combinations thereof.
 18. Theunit of claim 15, wherein the carbon oxide removal system comprises awater-gas shift reactor.
 19. The unit of claim 15, wherein the carbonoxide removal system comprises a methanation reactor.
 20. The unit ofclaim 15, wherein the hydrotreating reactor comprises more than one bedwith an interbed purge for each bed, each interbed purge in fluidcommunication with the carbon oxide removal system.
 21. The unit ofclaim 20, further comprising a separate hydrogen stream to each bed ofthe hydrotreating reactor.
 22. The unit of claim 15, wherein thehydrotreating reactor comprises a fluidized bed reactor and aregenerator for decoking catalyst from the fluidized reactor.
 23. Theunit of claim 22, wherein the regenerator decokes the catalyst withhydrogen, oxygen, steam, or combinations thereof.